A plunger lift assembly and method for using such an assembly is disclosed in U.S. Pat. Nos. 6,467,541 and 6,719,060, which are incorporated herein by reference in their entirety.
There are many different techniques for artificially lifting formation liquids from hydrocarbon wells. Reciprocating sucker rod pumps are the most commonly used because they are the most cost effective, all things considered, over a wide variety of applications. Other types of artificial lift include electrically driven down hole pumps, hydraulic pumps, rotating rod pumps, free pistons or plunger lifts and several varieties of gas lift. These alternate types of artificial lift are more cost effective than sucker rod pumps in the niches or applications where they have become popular. One of these alternative types of artificial lift is known as a plunger lift, which is basically a free piston that moves upwardly in the well to move formation liquids to the surface. Typically, plunger lifts are used in gas wells that are loading up with formation liquids thereby reducing the amount of gas flow. A free piston should be understood to be a piston that is not attached to a reciprocating member, but rather relies on fluids and fluid pressure to move the piston components.
Gas wells reach their economic limit for a variety of reasons. A very common reason is the gas production declines to a point where the formation liquids are not readily moved up the production string to the surface. Two phase upward flow in a well is a complicated affair and most engineering equations thought to predict flow are only rough estimates of what is actually occurring. One reason is the changing relation of the liquid and of the gas flowing upwardly in the well. At times of more-or-less constant flow, the liquid acts as an upwardly moving film on the inside of the flow string while the gas flows in a central path on the inside of the liquid film. The gas flows much faster than the liquid film. When the volume of gas flow slows down below some critical values, or stops, the liquid runs down the inside of the flow string and accumulates in the bottom of the well.
If sufficient liquid accumulates in the bottom of the well, the well is no longer able to flow because the pressure in the reservoir is not able to start flowing against the pressure of the liquid column. The well is said to have loaded up and died. Years ago, gas wells were plugged much quicker than today because it was not economic to artificially lift small quantities of liquid from a gas well. At relatively high gas prices, it is economic to keep old gas wells on production. It has gradually been realized that gas wells have a life cycle that includes an old age segment where a variety of techniques are used to keep liquids flowing upwardly in the well and thereby prevent the well from loading up and dying.
There are many techniques for keeping old gas wells flowing and the appropriate one depends on where the well is in its life cycle. For example, the first technique is to drop soap sticks into the well. The soap sticks and some agitation cause the liquids to foam. The well is then turned to the atmosphere and a great deal of foamed liquid is discharged from the well. Later in its life cycle, when soaping the well has become much less effective, a string of 1″ or 1½″ tubing is run inside the production string. The idea is that the upward velocity in the small tubing string is much higher which keeps the liquid moving upwardly in the well to the surface. A rule of thumb is that wells producing enough gas to have an upward velocity in excess of 10′/second will stay unloaded. Wells where the upward velocity is less than 5′/second will always load up and die.
As some stage in the life of a gas well, these techniques no longer work and the only approach left to keep the well on production is to artificially lift the liquid with a pump of some description. The logical and time tested technique is to pump the accumulated liquid up to the tubing string with a sucker rod pump and allow produced gas to flow up the annulus between the tubing string and the casing string. This is normally not practical in a 2⅞″ tubingless completion unless one tries to use hollow rods and pump up the rods, which normally doesn't work very well or very long. Even then, it is not long before the rods cut a hole in the 2⅞″ string and the well is lost. In addition, sucker rod pumps require a large initial capital outlay and either require electrical service or elaborate equipment to restart the engine.
Free pistons or plunger lifts are a common type of artificial pumping system to raise liquid from a well that produces a substantial quantity of gas. Conventional plunger lift systems comprise a piston that is dropped into the well by stopping upward flow in the well, as by closing the wing valve on the well head. The piston is often called a free piston because it is not attached to a sucker rod string or other mechanism to pull the piston to the surface. When the piston reaches the bottom of the well, it falls into the liquid in the bottom of the well and ultimately into contact with a bumper spring, normally seated in a collar or resting on a collar stop. The wing valve is opened and gas flowing into the well pushes the piston upwardly toward the surface, pushing liquid on top of the piston to the surface. Although plunger lifts are commonly used devices, there is as much art as science to their operation.
A major disadvantage of conventional plunger lifts is the well must be shut in so the piston is able to fall to the bottom of the well. Because wells in need of artificial lifting are susceptible to being easily killed, stopping flow in the well has a number of serious effects. Most importantly, the liquid on the inside of the production string falls to the bottom of the well, or is pushed downwardly by the falling piston. This is the last thing that is desired because it is the reason that wells load up and die. In response to the desire to keep the well flowing when a plunger lift piston is dropped into the well, attempts have been made to provide valved bypasses through the piston which open and close at appropriate times. Such devices are to date quite intricate and these attempts have so far failed to gain wide acceptance.
Recent development of multi-part plungers which may be dropped into a well while formation contents are flowing upwardly in the well as shown in U.S. Pat. Nos. 6,148,923, 6,209,637 6,467,541, 6,719,060 and 7,383,878. In the most recent development, as taught in currently pending parent application Ser. No. 14/472,044, a flow restriction member is releasably retained by a sleeve member such that the flow restriction member is not released from the sleeve member solely by the force of gravity. As will be more fully appreciated by the description of the invention below, if the flow restriction member prematurely releases from the sleeve member, such as by a sudden decrease in fluid pressure (“lift”), the sleeve and flow restriction member will separately drop in the well until at some point they are reunited and begin the upward journey once again. In many instances, the separate free piston components are not reunited until they reach the bottom of the well at which time the process starts once again, thus losing valuable time and exposing the well to potential fluid pressures that may cause the well to stop flowing.
In some of the prior art devices utilizing such a separate free piston assembly, the components are latched together before beginning the lift portion of the process. Such latching presents problems that are overcome by the assembly of the parent invention Ser. No. 14/472,044. Specifically, the latching requires that the flow restriction member be captured by a mechanical structure that hold the flow restriction member in place during the lift. Such latching can be conveniently implemented at the bottom of the well where other structure is available to prevent movement of the flow restriction member while it is being latched, but just the opposite is true if the joinder of the flow restriction member and the sleeve member are being joined at a location above the bottom of the well. In such instances, the latching mechanism can actually interfere with the seating of the flow restriction member in the sleeve member and may result in the unwanted loss of time in joining the free piston members. The latching structure also tends to be cumbersome to install and frequently wears out prior to the useful life of the free piston assembly being completed.
For certain applications, the use of heavier, one-piece bypass plungers is preferred such as, for example, when sand causes premature wear on other types of plungers (e.g. padded plungers), in more dense fluid wells, during clean-out of a well, during operation in minimum bottom hole pressure, during operation in either high or low Gas Liquid Ratios (GLR). The use of one-piece bypass plungers circumvents long shut-in times. Recent development of such one-piece plungers is shown in U.S. Pat. Nos. 7,438,125 and 9,068,443 as well as U.S. Pat. Publication No. 2015-0300136. There remains, however, a need in the field for a simpler design single piece bypass plunger with fewer components that can fail, a plunger that can fall even faster, and lifts a larger volume of fluids per run.
The current invention pertains to a one-piece, internal by-pass valve durable dart plunger that falls faster, produces more fluids and has a clutch assembly (also referred to here as spring loaded retention assembly (or grappler)) that is more durable and that can also be replaced when worn out.